Natural gas is primarily moved by pipelines on land. Where it is impractical or prohibitively expensive to move the product by pipeline, LNG shipping systems have provided a solution above a certain threshold of reserve size. With the increasingly expensive implementation of LNG systems being answered by economies of scale of larger and larger facilities, the industry has moved away from a capability to service the smaller and most abundant reserves. Many of these reserves are remotely located and have not been economical to exploit using LNG systems.
Recent work by the industry seeks to improve delivery capabilities by introducing floating LNG liquefaction plants and storage at the gas field and installing on board re-gasification equipment on LNG carriers for offloading gas offshore to nearby market locations that have opposed land based LNG receiving and processing terminals. To further reduce energy consumption by simplification of process needs, the use of pressurized LNG (PLNG) is once again under review by the industry for improvement of economics in an era of steeply rising costs for the LNG industry as a whole. See, e.g., U.S. Pat. Nos. 3,298,805; 6,460,721; 6,560,988, 6,751,985; 6,877,454; 7,147,124; 7,360,367.
The demanding economics of fringe area development of reserves of “stranded gas” worldwide dictate improvements of service beyond those offered by floating LNG and pressurized LNG technologies for full exploitation of this energy source.
The advent of Compressed Natural Gas (CNG) transportation systems, to cater to the needs of a world market of increasing demand, has led to many proposals in the past decade. However, during this same time period there has only been one small system placed into full commercial service on a meaningful scale. CNG systems inherently battle design codes that regulate wall thicknesses of their containment systems with respect to operating pressures. The higher the pressure, the better the density of the stored gas with diminishing returns—however, the limitations of “mass of gas-to-mass of containment material” have forced the industry to look in other directions for economic improvements on the capital tied up in CNG containment and process equipment. See, e.g., U.S. Pat. Nos. 5,803,005; 5,839,383; 6,003,460; 6,449,961, 6,655,155; 6,725,671; 6,994,104; 7,257,952.
One solution outlined in U.S. Pat. No. 7,607,310, which is incorporated herein by reference, provides a methodology to both create and store a liquid phase mix of natural gas and light-hydrocarbon solvent under preferred temperature conditions of below −40° to about −80° F. and preferred pressure conditions of about 1200 psig to about 2150 psig. The liquid phase mix of natural gas and light-hydrocarbon solvent is referred to hereafter as Compressed Gas Liquid (CGL) product or mixture. Although the CGL technology enables improved cargo density with the combination of lower process energy for a liquid state storage not attainable by LNG, PLNG and CNG systems and processes, the demanding economics of fringe area development of reserves dictate the need to increase cargo density, reduce process energy, and reduce containment vessel mass.
Accordingly, it is desirable to provide systems and methods that facilitate economic development of remote or stranded reserves to be realized by a means not afforded by LNG, PLNG or CNG systems and utilize CGL systems and process for natural gas storage to realize increased cargo density, reduction of process energy, and reduction in containment vessel mass inherent.